Mohamed A. Aggour

ARTIFICIAL NEURAL NETWORK MODEL FOR ACCURATE PREDICTION OF PRESSURE DROP IN HORIZONTAL AND NEAR-HORIZONTAL-MULTIPHASE FLOW

ABSTRACT Accurate prediction of pressure drop for multiphase flow in horizontal and near horizontal pipes is needed for effective design of flow lines and piping networks. The increased application of horizontal wells further signified the need for accurate prediction of pressure drop. Several correlations and mechanistic models have been developed since 1950. In addition to the limitations on the applicability of all existing correlations, they all fails to provide the desired accuracy of pressure drop predictions. The recently developed mechanistic models provided some improvements in pressure drop prediction over the empirical correlations. However, there is still a need to further improve the accuracy of prediction for a more effective and economical design of wells and surface piping networks. This paper presents an Artificial Neural Network (ANN) model for prediction of pressure drop in horizontal and near-horizontal multiphase flow. The model was developed and tested using field data covering a wide range of variables. A total of 225 field data sets were used for training- and 113 sets data for cross-validation of the model. Another 112 sets of data were used to test the prediction accuracy of the model and compare its performance against existing correlations and mechanistic models. The results showed that the present model significantly outperforms all other methods and provides predictions with accuracy that has never been possible. A trend analysis was also conducted and showed that the present model provides the expected effects of the various physical parameters on pressure drop.

Effect of electroosmosis on relative permeabilities of sandstones

Abstract Dynamic displacement experiments were performed to investigate the effect of electroosmosis on relative permeability. Berea sandstone cores, Arabian light crude oil and a 20 g/l NaCl aqueous solution were used. Direct electrical potential gradients of up to 3 V/cm were applied across the core with the cathode placed at the injection end. The application of the electrical potential gradient increased the oil relative permeability and decreased the water relative permeability. The changes in relative permeabilities increased with increasing the applied electrical potential gradient. The breakthrough water saturation at the outlet end generally shifted towards successively higher values with increasing electrical potential gradients, and the two-phase flow period increased resulting in higher breakthrough and ultimate recoveries.

Investigation of waterflooding under the effect of electrical potential gradient

Abstract An experimental study has been conducted to investigate the effect of electrical potential gradient on oil recovery, water, production and water-oil ratio during water flooding. The experiments were performed using a linear model packed with 30 40 mesh sand. Oil of 28.7° API gravity and water having 30,000 ppm NaCl were used in the experiments. Direct electrical potential gradients ranging from 0.5 to 7.5 V/cm were examined. The potential gradient was applied across the oil-water bearing formation such that the injection end was the cathode and the production end was the anode. It was found that the application of the direct electrical potential gradient results in increasing the oil recovery and reducing water production and water-oil ratio ( WOR ). Further, these effects were directly proportional to the increase in the applied electrical potential difference, and were only appreciable after water breakthrough.

Experimental study of horizontal well performance in fractured reservoirs with bottom-water drive

An experimental investigation has been conducted to study the production performance of horizontal wells with single- and multiple orthogonal fractures in bottom water drive reservoirs. The effect of the number of fractures intersecting the well and of the vertical penetration and horizontal extension of the fracture on production performance has been studied. A scaled three-dimensional rectangular model, representing the drainage volume for a single horizontal well in one of the Middle East reservoirs, has been used. The model was packed with glass beads yielding a porosity of 0.36 and a permeability of 400 Darcies. Kerosene and distilled water were used to represent the reservoir fluids. The production rate was chosen so that the oil-water interface would remain stable until it approaches the producing well. The fractured wells provided much better performance than the un-fractured well, yielding higher oil recovery and delayed water breakthrough. Increasing the number of orthogonal fractures improved the production performance of the well. However, there is a limit beyond which no further improvement in the performance would be possible. Similarly, increasing the fracture penetration and/or extension improved the production performance up to a limit beyond which no further improvement was obtained. *Currently with Qatar Gas Company.

HELE-SHAW MODEL STUDY OF HORIZONTAL WELL PERFORMANCE IN RESERVOIR WITH GAS CAP AND BOTTOM WATER DRIVE

The production performance of horizontal wells under simultaneous gas-cap and bottom-water drive has been investigated experimentally using a 2-dimensional Hele-Shaw model. Experiments were conducted using different well locations, relative to the gas–oil and water–oil interfaces, and different production rates at each well location with the objective of determining the optimum well location and production rate. The model, which represented a vertical section of the reservoir perpendicular to the well, consisted of two plexiglass plates 40 cm high and 120 cm long with a 0.04 cm capillary space in between. Nine wells, represented by 0.3175 cm diameter holes, were provided along the height and at the center of the model. The oil used was synthetic oil with a viscosity of 4.6 cP and a density of 0.83 g/cc, while the water was represented by a glycerol–-water solution with a viscosity of 3.26 cP and a density of 1.08 g/cc. Nitrogen was used to represent the gas phase. The model and fluids characteristics were chosen to simulate conditions for one of the major reservoirs in the Middle East. Video and still photography were used to track the movement of the water–oil and gas–oil interfaces. It was found that the well is optimally located if the ratio of the distance between the well and the water–oil interface to that between the well and the gas oil–interface is 3:5. This well location provided the highest recovery and latest breakthrough at all production rates. It was also found that better well performance (i.e., higher recovery, later water breakthrough and lower water cut) is obtained at higher than at lower production rates provided that the gas–oil and water–oil interfaces remain stable and flat as they move towards the well.

IMPROVING SANDSTONE MATRIX STIMULATION OF OIL WELLS BY GAS PRECONDITIONING

ABSTRACT Experience has shown that for sandstone formations, oil wells respond to matrix acidizing in a different manner as compared to gas wells. For oil wells, the improvement in permeability resulting from the stimulation treatment peaks at a certain acid volume and then drops as the volume of acid injected increases. For gas wells, however, the resulting improvement in permeability is roughly proportional to the volume of acid injected, and is normally better than that obtained with oil wells. It is, therefore, expected that stimulation of oil wells in sandstone formations could be improved by displacing the oil in the zone to be treated with gas. Gas injection prior to acidizing is sought to minimize the formation of emulsions or sludge resulting from reactions between the spent acid products and the oil that otherwise would be contacted. This paper presents the results of an experimental investigation on the effect of gas pre-conditioning of the damaged oil-bearing sand on permeability improvement by matrix acidizing. Experiments were conducted on Berea sandstone cores saturated with 29.2°API crude oil at actual reservoir temperature of 180°F and pressure of 3000 psi. Carbon dioxide and nitrogen were separately used for pre-conditioning prior to stimulation and the results were compared against stimulation without gas pre-conditioning. It was found that with regular stimulation, improvement in permeability peaked at a certain acid volume. With gas (CO2 or N2) pre-conditioning, however, continuous improvement in permeability was obtained with increasing the volume of acid injection. Further, using gas pre-conditioning with a small volume of acid (that would otherwise not be sufficient to even recover the original permeability with regular acidizing) resulted in permeability improvements of up to 200% of the original pre-damage permeability. At an acid volume that would just restore the original permeability with regular stimulation, gas pre-conditioning resulted in permeability improvement close to 300% of the original permeability. Pre-conditioning with either CO2 or N2 provided superior results compared to regular stimulation. However, CO2 was found to be more effective than N2. This is attributed to the fact that CO2 has better miscibility than N2 and would, therefore, provide more efficient displacement of the oil out of the zone to be stimulated.

Improving Sandstone Matrix Acidizing for Oil Wells by Gas Preconditioning

Experience has shown that for sandstone formations, oil wells respond to matrix acidizing in a different manner as compared to gas wells. For oil wells, the improvement in permeability resulting from the stimulation treatment peaks at a certain acid volume and then drops as the volume of acid injected increases. For gas wells, however, the resulting improvement in permeability is roughly proportional to the volume of acid injected, and is normally better than that obtained with oil wells. It is, therefore, expected that stimulation of oil wells in sandstone formations could be improved by displacing the oil in the zone to be acidized with gas. Gas injection prior to acidizing is sought to minimize the formation of emulsions or sludges between the spent acid products and the oil that otherwise would be contacted. This paper presents the results of an experimental investigation on the effect of gas pre-conditioning of the damaged sand on permeability improvement by matrix acidizing. Experiments were conducted on Berea sandstone cores saturated with 29.2 °API crude oil at selected reservoir conditions of 180 °F and 3000 psi pore pressure. Carbon dioxide and nitrogen were separately used for pre- conditioning prior to stimulation and the results were compared against stimulation without gas pre-conditioning. It was found that with regular stimulation, improvement in permeability peaked at a certain acid volume. With gas (CO 2 or N 2 ) pre-conditioning, however, continuous improvement in permeability was obtained with increasing the volume of acid injection. Further, using gas pre-conditioning with a small volume of acid (that would otherwise not be sufficient to even recover the original permeability with regular acidizing) resulted in permeability improvements of up to 200% of the original pre-damage permeability. At an acid volume that would just restore the original permeability with regular stimulation, gas pre-conditioning resulted in permeability improvement close to 300% of the original permeability. Pre-conditioning with either CO 2 or N 2 provided superior results compared to regular stimulation. However, CO 2 was found to be more effective than N 2 . This is attributed to the fact that CO 2 has better miscibility than N 2 and would, therefore, provide more efficient displacement of the oil out of the zone to be stimulated.

Performance comparison of fractured and un-fractured vertical and horizontal wells in reservoirs with bottom-water drive

ABSTRACT An experimental investigation, using a scaled three- dimensional rectangular model, has been conducted to study the production performance of un-fractured and fractured vertical wells under bottom water drive. The results are compared against those for un-fractured horizontal wells and horizontal wells with orthogonal and longitudinal fractures. The model represented a section of the drainage volume for a single horizontal well in one of the Middle East reservoirs. Kerosene and distilled water were used to represent the reservoir fluids, while glass beads were used to represent the porous medium. All experiments were conducted at the same production rate, which was chosen so that the oil–water interface would remain stable until it approaches the producing well. As expected, fracturing vertical wells greatly improves their performance by increasing oil recovery at breakthrough and ultimate recovery, delaying water breakthrough and reducing pressure drop. While horizontal wells have, in general, better performance than vertical wells, fractured vertical wells perform better than horizontal wells with regard to recovery, water breakthrough and pressure drop. Horizontal wells with orthogonal or longitudinal fractures are found to be superior to fractured vertical wells. In general, increasing the fracture penetration improved the production performance of both vertical and horizontal wells. Interestingly, it was found that extending the fracture penetration towards the original oil–water contact did not, as might have been expected, result in earlier water breakthrough.

PERFORMANCE OF HORIZONTAL WELLS WITH LONGITUDINAL FRACTURES IN RESERVOIRS WITH BOTTOM-WATER DRIVE

The production performance of un-fractured horizontal wells and horizontal wells with longitudinal fractures of various vertical penetrations in reservoirs with bottom water drive has been studied using a scaled three-dimensional rectangular model. The model represented the drainage volume for a single horizontal well in one of the Middle East reservoirs. The model was packed with glass beads yielding a porosity of 0.36 and a permeability of 400 Darcies, and kerosene and distilled water were used to represent the reservoir fluids. The production rate was chosen so that the oil–water interface would remain stable until it approaches the producing well. In general, wells with greater contact area with the reservoir gave higher oil recovery before water breakthrough, and experienced lower pressure drop. Increasing the fracture penetration improved the production performance up to a limit beyond which no further improvement was obtained. Interestingly, it was found that extending the fracture penetration towards the original oil–water contact did not, as might have been expected, result in earlier water breakthrough. The fracture acted as an in situ oil–water separator and an equilibrium water level was maintained within the fracture as long as the oil–water interface was flat as it moved upward towards the well. *Currently with Qatar Gas Company.